Following the failure of the initial well in the Marlin field1 the preferred solution for completing the remaining wells was to control wellbore temperature via vacuum insulated tubing (VIT)2. Implementation of VIT required a number of computational and experimental innovations, including:Provision for insulating the tubing couplings, the source of up to 90% of VIT heat loss;Detailed flow loop temperature profiles using both axial probes and radial probes traversing the annulus outside the VIT. These profiles supplemented the conventional values of overall heat transfer coefficient and thermal conductivity obtained from the flow loop measurements;VIT performance, as measured experimentally, must exceed both thermal and mechanical design bases. As well survival depends on proper VIT performance, a distributed temperature monitoring system was developed and evaluated during full scale testing. On the Marlin TLP, fiber optic is run in each well along the length of the VIT to continuously monitor the production annulus temperature profile. A software system was also developed to take binary fiber data and feed an integrated thermal simulator-casing design software package that calculates safety factors for the B and C annuli. These real time safety factors interface with the platform alarm system and are continually monitored by operators. If a low safety factor is calculated, a well will be shut-in. In addition to feeding the platform alarm system, the software provides data to a web based plotting program. If a single joint of VIT loses its insulating properties, this specific joint can be identified and appropriate action taken. The monitoring system has also proved to be a valuable quality assurance measure for special annular gels used to minimize conduction and natural convection in the production annulus. This paper focuses on the value of the combined VIT and fiber/software monitoring system as a means of both controlling and observing well thermal behavior. Typical temperature vs. depth curves are used to illustrate the detailed information retrieved. Introduction Despite an extensive effort to ascertain a root cause of the collapse of the (10–3/4 in. × 8–5/8 in.) production tieback and ensuing deformation of the production tubing in Marlin Well A-2, a singular mechanism could not be discerned. This lack of resolution is primarily due to the fact that the status of the (13–3/8 in. × 10–3/4 in.) intermediate casing is unknown. Nevertheless, all possible root causes which the investigation team deemed reasonable had as a component an increase in temperature of the wellbore. This fact, coupled with the limited options available from the batch drilled wellbores, led the team to focus on controlling wellbore temperature by insulating the production tubing. Vacuum insulated tubing (VIT), even apart from its cost, is, unfortunately, a solution with its own set of design challenges. Thermally, it must, of course, be substantiated that the thermal characteristics are sufficient to solve the problem - that is, to keep the annuli sufficiently cool to render the well safe. For Marlin, this requirement was satisfied in two ways - by experimentally determining the overall heat transfer coefficient of VIT targeted for Marlin wellbores and by numerically modeling the resulting thermal performance of the VIT under a production scenario. The discussion below details the latter exercise, the former being addressed in the preceding paper in this series2. Further, validation of adequate thermal performance must be supplemented by checking the mechanical integrity of the VIT under a variety of burst, collapse and tension load cases.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractInjection well performance over the long term is often critically dependent upon how the well has been operated during its commissioning period. Whether the well is ultimately to be a seawater (or fresh water) injector or to be used for produced water re-injection, it may be beneficial to commission the well with a different water, probably at a different temperature, since this can have a marked effect upon the initiation of thermal fractures (more precisely these are usually in fact hydraulic fractures that have been initiated at reduced fracture gradients due to near wellbore reservoir cooling).In long horizontal injectors it is likely that several separate thermal fractures may be generated, and their creation needs to be controlled and managed to ensure optimum well performance. To generate a procedure for the well commissioning requires us to be able to predict bottom hole injection temperature, rate and pressure variation along the horizontal (or highly deviated) section and couple this into a reservoir fracture model. Achieving this using separate models soon becomes impractical, requiring too may iterations between coupled problems. This paper presents an overview of how an existing commercially available transient wellbore model has been coupled to a special purpose reservoir simulator, and how this has been applied to the modelling of multiple thermal fractures in horizontal injection wells. The paper also reports how the wellbore simulator has been modified to allow the prediction of depth dependent bottom hole temperatures. The paper will also comment on the application of this new coupled model to intervention work in production wells.
The redesign solution for the batch-drilled wells remaining after the deformation of the Marlin Well A-2 production tieback and tubing was vacuum-insulated tubing (VIT). VIT implementation, however, required a number of computational and experimental innovations.To ensure well survival, a distributed temperature-monitoring system was developed and evaluated during full-scale VIT testing. Fiber-optic cable run on completions continuously monitors the production-annulus temperature profile. The monitoring system has also proved to be a valuable quality-assurance measure for special annular gels used to minimize conduction and natural convection in the production annulus. AbstractFollowing the failure of the initial well in the Marlin field, 1 the preferred solution for completing the remaining wells was to control wellbore temperature by means of VIT. 2 Implementation of VIT required a number of computational and experimental innovations, including:• Provision for insulating the tubing couplings, the source of up to 90% of VIT heat loss.• Detailed flow-loop temperature profiles with both axial and radial probes traversing the annulus outside the VIT. These profiles supplemented the conventional values of the overall heattransfer coefficient and thermal conductivity obtained from the flow-loop measurements.• VIT performance, as measured experimentally, must exceed both thermal and mechanical design bases.Because well survival depends on proper VIT performance, a distributed temperature-monitoring system was developed and evaluated during full-scale testing. On the Marlin tension-leg platform (TLP), fiber-optic cable is run in each well along the length of the VIT to monitor the production-annulus temperature profile continuously. A software system was also developed to feed binary fiber data to an integrated thermal-simulator casing-design software package that calculates safety factors for the B and C annuli. These real-time safety factors interface with the platform alarm system and are continually monitored by operators. If a low safety factor is calculated, a well will be shut in. In addition to feeding the platform alarm system, the software provides data to a web-based plotting program. If a single VIT joint loses its insulating properties, this specific joint can be identified, and appropriate action can be taken. The monitoring system has also proved to be a valuable quality-assurance measure for special annular gels used to minimize conduction and natural convection in the production annulus.This paper focuses on the value of the combined VIT and fiber/software monitoring system as a means of both controlling and observing well thermal behavior. Typical temperature vs. depth curves are used to illustrate the detailed information retrieved.
When a well that has been producing a mixture of oil, water and gas is shut-in for an extended period of time, the fluid columns expand or contract in response to the temperature changes in the well. These changes in fluid levels in turn, affect the heat transfer in and around the wellbore. This coupled problem of determining the fluid levels as well as the wellbore temperature distribution is addressed. An algorithm is proposed, implemented and discussed for a hydrocarbon that can be modeled as a black-oil. Special cases of the algorithm when one of the phases is absent are also included. This model helps accurate and rigorous prediction of the wellbore temperature distribution and the wellhead pressure during a shut-in. Accurate temperature and pressure estimates in turn lead to better stress calculations to ensure the design of the wellbore with improved integrity of the tubulars. Introduction The problem of determining the wellhead pressure in a well that has been shut-in following the production of hydrocarbons and associated water is of interest to several aspects of the upstream oil industry such as production optimization, well design, well safety monitoring, etc. The wellhead pressure in such a well is a function the shut-in time period and is dependent on of the reservoir fluid characteristics, the proportions of the different fluid phases, the temperature profile in the wellbore at the start of the shut-in period, the far-field undisturbed temperature profile for the well trajectory. In general, immediately after the shut-in the fluids in the well re-arrange themselves in response to the buoyancy forces, with the water settling to the bottom, gas moving to the top and an oil layer forming between the two. This process of rearrangement of fluids is transient and generally lasts a short time. In this paper, this transient process is not addressed; instead, the focus is on the subsequent wellbore processes. Specifically, an analysis is presented on the question of how the fluid interface levels in the wellbore change with time in response to changes in the wellbore temperatures and in the reservoir pressure over the shut-in period, and how they affect the wellhead pressure. The changes in the fluid composition and properties with the changes in pressure and temperature at any location in the wellbore are vital to this analysis. Also not included in the analysis is the transient build up of the reservoir pressure at the perforations. The pressure build up occurs over a short period of time, and this period largely coincides with the transient fluid rearrangement period. The analysis presented here starts with the state of the reservoir subsequent to the transient pressure build up. It is assumed that the proportions of the hydrocarbon fluid and the water in the reservoir, represented by the standard conditions gas-oil-ratio (GOR) and water-oil-ratio (WOR), stay fixed over the shut-in period. The analysis presented here can be readily adapted to the case where these ratios change over time in a prescribed manner. These ratios are assumed to be unaffected by the movements of the fluids in or out of the wellbore during the shut-in. It is assumed that the proportion of the fluids in the wellbore stays consistent with these reservoir fluid ratios over the period of the shut-in; this assumption should hold due to the fluid equilibration owing to the diffusion process over the time periods considered in the present analysis. The nature of the hydrocarbon fluid in the wellbore is also important to the problem under consideration. It is customary in the industry to model the hydrocarbon fluid as either as a black-oil or as a gas condensate fluid (Whitson and Brule1). In this work, a full treatment of the case with black-oil fluids is provided. A discussion is presented to outline the difference in the processes in the shut-in well with these two fluid types; this explains why this solution is not applicable to the gas condensate fluid case and points to the need for additional development in this area.
Therapy for ischaemic congestive heart failure has been well documented in patients with angina. The goal of this study was to compare the benefit of revascularization in patients with and without chest pain. A series of 180 patients with ischaemic heart failure symptoms (New York Heart Association III-IV class) and low ejection fraction (28^9%) were recruited and followed for 3 years. Group A, 97/180 patients, had chest pain. Group B, 83/180 patients, did not have angina. The two groups did not differ with respect to known determinants of postinfarction prognosis. The relative presence of viable tissue versus scar was defined by Thallium-201 uptake. Intraoperative mortality was 5 and 7% in Groups A and B (P ¼ not significant); in particular, in both groups, it was lower when only patients with mostly viable myocardium were considered. At 6 months, the presence of viable myocardium was highly predictive of improvement of heart failure symptoms and wall motion abnormalities. At 3 years, revascularized patients of Group A with mostly viable myocardium had a survival of 89% compared to 87% for corresponding Group B patients (P ¼ not significant). In conclusion, similarly to patients with angina, patients with left ventricular dysfunction, maintained viability and without anginal symptoms may benefit from coronary revascularization. q 2002 Published by Elsevier Science B.V.
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